1. Field of the Invention
The present invention relates to wellbore completion. More particularly, the invention relates to effectively increasing the carrying capacity of the circulating fluid without damaging wellbore formations. More particularly still, the invention relates to removing cuttings in a wellbore during a drilling operation.
2. Description of the Related Art
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling a predetermined depth, the drill string and bit are removed, and the wellbore is lined with a string of casing with a specific diameter. An annular area is thus defined between the outside of the casing and the earth formation. This annular area is filled with cement to permanently set the casing in the wellbore and to facilitate the isolation of production zones and fluids at different depths within the wellbore.
It is common to employ more than one string of casing in a wellbore. In this respect, a first string of casing is set in the wellbore when the well is drilled to a first designated depth. The well is then drilled to a second designated depth and thereafter lined with a string of casing with a smaller diameter than the first string of casing. This process is repeated until the desired well depth is obtained, each additional string of casing resulting in a smaller diameter than the one above it. The reduction in the diameter reduces the cross-sectional area in which circulating fluid may travel.
Typically, fluid is circulated throughout the wellbore during the drilling operation to cool a rotating bit and remove wellbore cuttings. The fluid is generally pumped from the surface of the wellbore through the drill string to the rotating bit. Thereafter, the fluid is circulated through an annulus formed between the drill string and the string of casing and subsequently returned to the surface to be disposed of or reused. As the fluid travels up the wellbore, the cross-sectional area of the fluid path increases as each larger diameter string of casing is encountered. For example, the fluid initially travels up an annulus formed between the drill string and the newly formed wellbore at a high annular velocity due to small annular clearance. However, as the fluid travels the portion of the wellbore that was previously lined with casing, the enlarged cross-sectional area defined by the larger diameter casing results in a larger annular clearance between the drill string and the cased wellbore, thereby reducing the annular velocity of the fluid. This reduction in annular velocity decreases the overall carrying capacity of the fluid, resulting in the drill cuttings dropping out of the fluid flow and settling somewhere in the wellbore. This settling of the drill cuttings and debris can cause a number of difficulties to subsequent downhole operations. For example, it is well known that the setting of tools against a casing wall is hampered by the presence of debris on the wall.
Several methods have been developed to prevent the settling of the drill cuttings and debris by overcoming the deficiency of the carrying capacity of the circulating fluid. One such method is used in a deepwater application where the increased diameter of the drilling riser results in a lower annular velocity in the riser system. Generally, fluid from the surface of the floating vessel is injected into a lower portion of the riser system through a flow line disposed on the outside of the riser pipe. This method is often referred to as “charging the riser”. This method effectively increases the annular velocity and carrying capacity of the circulating fluid to assist in wellbore cleaning. However, this method is not practical for downhole operations.
Another method to prevent the settling of the drill cuttings and debris is by simply increasing the flow rate of the circulating fluid over the entire wellbore interval to compensate for the lower annular velocity in the larger annular areas. This method increases the annular velocity in the larger annular areas, thereby minimizing the amount of settling of the drill cuttings and debris. However, the higher annular velocity also increases the potential of wellbore erosion and increases the equivalent circulating density, which deals with the friction forces brought about by the circulation of the fluid. Neither effect is desirable, but this method is often used by operators to compensate for the poor downhole cleaning due to lower annular velocity of the circulating fluid.
Potential problems associated with flow rate and the velocity of return fluid while drilling are increased when the wellbore is formed by a technique known as “drilling with casing”. Drilling with casing is a method where a drill bit is attached to the same string of tubulars that will line the wellbore. In other words, rather than run a drill bit on smaller diameter drill string, the bit is run at the end of larger diameter tubing or casing that will remain in the wellbore and be cemented therein. The bit is typically removed in sections or destroyed by drilling the next section of the wellbore. The advantages of drilling with casing are obvious. Because the same string of tubulars transports the bit as lines the wellbore, no separate trip into the wellbore is necessary between the forming of the wellbore and the lining of the wellbore.
Drilling with casing is especially useful in certain situations where an operator wants to drill and line a wellbore as quickly as possible to minimize the time the wellbore remains unlined and subject to collapse or to the effects of pressure anomalies. For example, when forming a subsea wellbore, the initial length of wellbore extending from the ocean floor is much more subject to cave in or collapse due to soft formations as the subsequent sections of wellbore. Sections of a wellbore that intersect areas of high pressure can lead to damage of the wellbore between the time the wellbore is formed and when it is lined. An area of exceptionally low pressure will drain expensive circulating fluid from the wellbore between the time it is intersected and when the wellbore is lined.
In each of these instances, the problems can be eliminated or their effects reduced by drilling with casing. However, drilling with casing results in a smaller annular clearance between the outer diameter of the casing and the inner diameter of the newly formed wellbore. This small annular clearance causes the circulating fluid to travel through the annular area at a high annular velocity, resulting in a higher potential of wellbore erosion compared to a conventional drilling operation.
A need therefore exists for an apparatus and a method for preventing settling of drill cuttings and other debris in the wellbore during a drilling operation. There is a further need for an apparatus and a method that will effectively increase the carrying capacity of the circulating fluid without damaging wellbore formations. There is yet a further need for a cost-effective method for cleaning out a wellbore while drilling with casing.